Search Results (650)

China hosts abundant coal-rock gas (CRG) resources, which have become a critical unconventional natural gas contributor to national reserve expansion and production increment. Supercritical carbon dioxide (ScCO₂) fracturing is recognized as a green and efficient stimulation technology, exhibiting great potential for high-efficiency CRG exploitation. To clarify the effects and intrinsic mechanisms of ScCO₂ treatment on coal fracture initiation, propagation, and CRG recovery enhancement, true triaxial fracturing and CO₂-CH₄ displacement experiments were performed in combination with multiple microscopic characterization methods, including X-ray diffraction (XRD), Fourier-transform infrared spectroscopy (FTIR), and Scanning electron microscopy (SEM). The multi-scale experimental investigation systematically revealed the fracture development mechanism, permeability variation characteristics, and microstructural evolution of coal reservoirs under ScCO₂ interactions. The results indicate that ScCO₂ fracturing significantly lowers the coal fracture initiation threshold compared with conventional hydraulic fracturing, with the breakdown pressure reduced by 26.2% and the initiation time shortened by 37.5%. Such advantages facilitate coal fracture activation and the development of complex fracture networks. Long-term ScCO₂ soaking induces the dissolution of inorganic minerals (e.g., calcite, plagioclase, and clay minerals) and the extraction of inherent organic matter within coal matrices. The coupled hydro-chemical reactions reconstruct the coal pore structure, enlarge pore throats, and improve reservoir permeability, achieving a maximum permeability enhancement of approximately 1.6 times. Meanwhile, ScCO₂ displacement yields a prominent CRG recovery performance, with an ultimate gas recovery factor up to 93.85%. The CRG enhancement mechanism of ScCO₂ fracturing is comprehensively attributed to three core coupled effects. First, ScCO₂ dynamic fracturing generates intricate fracture networks, which greatly optimize reservoir seepage channels and flow space. Second, the ScCO₂–formation water–coal interaction modifies coal physical properties via mineral dissolution and organic matter extraction, thereby improving reservoir permeability. Third, the preferential adsorption of CO₂ over CH₄ triggers effective competitive adsorption and gas displacement, further promoting adsorbed methane desorption and elevating CRG recovery efficiency. This study provides a solid theoretical foundation for the field application of ScCO₂ fracturing technology and offers valuable insights into the green, efficient, and sustainable development of deep coal-rock gas resources. Full article

Hydraulic fracturing is a key stimulation technique for enhancing the permeability of tight sandstone-hosted uranium deposits. However, existing hydraulic fracture network evaluation methods are primarily applicable to stress regimes in which the vertical principal stress exceeds the horizontal principal stress, making them unsuitable for evaluating low-angle or subhorizontal hydraulic fractures formed under high-horizontal-stress and low-vertical-stress conditions. To address this limitation, this study develops a semi-quantitative method for evaluating hydraulic fracturing effectiveness under stress regimes characterized by high horizontal stress and low vertical stress. The proposed method introduces a Stoneley-wave attenuation index and combines it with Stoneley-wave chevron-apex responses to identify hydraulically fractured intervals. By further integrating conventional well-log data to reduce interference from borehole enlargement, lithological boundaries, and natural fractures, the method supports the identification of hydraulically induced fractures and provides a semi-quantitative assessment of their development. The method was applied to a hydraulic fracturing pilot test for in situ leaching uranium mining in the Bayingobi Basin, Alxa, China, where it supported the identification of hydraulically induced fractures and fractured intervals in both stimulation and monitoring wells. Field application results support the engineering applicability of the proposed method and provide preliminary validation of its effectiveness. The results indicate that this method provides an effective logging-based approach for evaluating hydraulic fracturing performance and investigating fracture propagation in tight sandstone-hosted uranium deposits. Full article

Fracturing is the dominant stimulation technique for low-porosity, low-permeability dolomite gas reservoirs, yet the lack of systematic laboratory research on multistage alternating acid etching mechanisms restricts field construction parameter optimization. Targeting the low-permeability Xixiangchi Formation dolomite reservoir in the eastern Sichuan Basin, this work develops a high-temperature, high-pressure core acid etching system coupled with 3D surface scanning. A reliable lab-to-field parameter conversion is established based on the Reynolds and Froude similarity criteria. Four-factor three-level orthogonal tests are conducted to quantify the impacts of pad fluid-to-acid viscosity ratio, total acid volume, pumping rate, and alternating injection stages on JRC-characterized wall roughness and fracture conductivity. The results show an identical factor dominance ranking for both indicators: viscosity ratio > pumping rate > injection stages > total acid volume. The optimal stimulation scheme is determined as a 50:1 viscosity ratio, 120 mL total acid volume, 12.54 mL/min laboratory pumping rate (equivalent to 8 m³/min in field operations), and 3 alternating injection stages. An elevated viscosity ratio intensifies viscous fingering, induces heterogeneous dolomite dissolution, and forms abundant irregular asperities on fracture surfaces. These self-supporting rough structures sustain stable seepage channels and markedly improve conductivity, verifying the positive roughness-conductivity correlation and revealing the core mechanism of heterogeneous etching-driven conductivity enhancement. The findings provide direct experimental support and parameter guidance for multistage alternating acid fracturing design in the Xixiangchi Formation and analogous tight dolomite reservoirs. Full article

Background: Hyponatraemia is the commonest electrolyte disturbance encountered in older adults admitted with neck of femur (NOF) fracture. It is now recognised both as associated with fragility fracture and as an independent prognostic indicator for adverse post-operative outcomes. Methods: Narrative review of the literature, with emphasis on cohort studies, meta-analyses and mechanistic investigations pertinent to hip fracture in adults. Results: Admission hyponatraemia affects approximately 13–20% of NOF patients, twice the prevalence observed in age-matched community-dwelling elders and broadly comparable to general geriatric inpatients. A further 20–30% develop in-hospital, predominantly post-operative, hyponatraemia. Mild hyponatraemia (130–135 mmol/L) accounts for 75–85% of cases. Pathophysiology is multifactorial: hypovolaemia from the fracture haematoma, fasting and pre-admission “long lie”; drug effects (thiazides, selective serotonin reuptake inhibitors (SSRIs), proton pump inhibitors, carbamazepine, opioids); and non-osmotic arginine vasopressin (AVP) release driven by pain, nausea and peri-operative stress. Chronic hyponatraemia is hypothesised to contribute to fracture risk through three convergent mechanisms, direct sodium-dependent stimulation of osteoclastogenesis with AVP-mediated bone resorption, subtle cerebral dysfunction producing gait and attention deficits, and sarcopenia, although much of this mechanistic evidence derives from animal and in vitro studies rather than from patients with hip fracture. Hyponatraemia is reproducibly associated with longer length of stay, delayed surgery, and an adjusted 30-day mortality hazard of approximately 1.15–1.40. A dose–response relationship with severity is demonstrable; pre-operative correction has not been shown to improve outcomes in any randomised trial. Conclusions: Hyponatraemia in NOF fracture is consistently a consequence of the acute event and, at minimum, a robust marker of frailty and adverse prognosis. Whether it also causally contributes to fracture risk remains unproven, since the supporting human evidence is entirely observational and mechanistic, each contributing study carries methodological weaknesses that warrant caution, and no interventional study has established causality. Where hyponatraemia is mild and isolated, current evidence does not support delaying surgery; moderate and severe hyponatraemia warrant individualised assessment, with cautious correction proceeding alongside surgical planning rather than postponing it. Given the absence of interventional evidence, no correction strategy can yet be recommended to improve fracture or surgical outcomes. Prospective trials of targeted correction strategies and rehabilitation outcomes are overdue. Full article

This study addresses the poorly understood fracture propagation mechanisms in continental shale oil reservoirs with multi-lithologic combinations, specifically those in the lower third member of the Shahejie Formation, Bonan Sag, which exhibit complex lithology, coexistence of bedding planes and natural fractures, and pronounced mechanical anisotropy. We conduct small scale true triaxial hydraulic fracturing physical simulation experiments using limestone mudstone, felsic–lime mixed shale, and their combined rock samples. We innovatively introduce the hydraulic fracture complexity coefficient (F_h), the bedding plane fracture complexity coefficient (F_l), and the comprehensive fracture complexity coefficient (F_T) to enable quantitative evaluation of fracture complexity. The results show that high-viscosity fracturing fluid promotes vertical propagation and improves proppant placement, but yields relatively simple fracture geometry. Low-viscosity fracturing fluid readily activates bedding plane fractures, yet limits fracture height; a combined viscosity strategy can synergistically optimize the overall fracturing performance. The “high–low–high” viscosity sequence achieves the highest comprehensive fracture complexity coefficient (F_T), simultaneously providing large fracture height, high complexity, and effective proppant transport. Although increasing the injection rate significantly reduces the breakdown pressure and increases fracture width, it contributes marginally to vertical fracture growth. For fracturing multi-lithologic shale oil reservoirs, the recommended technical strategy is a “high-low-high” viscosity sequence combined with a moderately increased injection rate” to maximize the stimulated reservoir volume and overall fracturing effectiveness. Full article

In conventional hydraulic fracturing of low-permeability sandstone reservoirs, polymer-gel leak-off creates low-permeability filter cakes that impair productivity. This study proposes a prepad acid fracturing technique using a fluoroboric acid (HBF₄) pre-flush to dissolve gel residues and mineral fines. A fully coupled mathematical model integrates HBF₄ hydrolysis kinetics, multi-mineral surface reactions, porosity-permeability evolution via the Panda–Lake model, and dynamic leak-off coefficient feedback. Simulations show HBF₄ decreases monotonically along the fracture while HF peaks at 40–60 m from wellbore. Acid concentration in the leak-off zone decays exponentially, defining a gel-dissolution zone within 0.5 m of the fracture wall. Acid dissolution increases near-wall porosity to 12–15% and permeability to 2.5–3.5 mD (3- to 4-fold). The leak-off coefficient varies dynamically: high in the acid-dominated zone (1.5–2.2 × 10⁻³ m/√min) favoring gel dissolution, and low in the gel-dominated zone (≈0.8 × 10⁻³ m/√min) promoting fracture extension. Compared with conventional polymer gel fracturing, the proposed method achieves a 15.9% higher stimulation ratio and 22.5% higher productivity after 100 days, despite slightly shorter fractures. The core advantage is restoring leak-off zone permeability from 0.45 mD to 0.85 mD and increasing gel filter cake permeability from 8 × 10⁻⁴ mD to 0.1 mD, with an average relative error of 8.2% against experimental data. These findings provide theoretical guidance for optimizing prepad acid fracturing in gel-damaged low-permeability sandstones. Full article

Stacked coalbed methane (CBM) reservoirs can increase the drainage thickness of a single well, but commingled production is influenced by stress-sensitive permeability, gas desorption, water drainage, and interlayer heterogeneity. This study presents a three-segment reservoir model for well GP-2 in the Tucheng block. Pore-fracture compressibility was estimated from overburden low-field nuclear magnetic resonance measurements and compared with stress-dependent permeability obtained by the pulse-decay method. The resulting coefficient was used in the dynamic permeability relationship and held fixed during history matching. The model was calibrated against gas- and water-production data from the first 240 d. One-factor simulations were then run over a common 3000 d calculation window to compare the relative responses to geological, adsorption, and stimulation parameters. In the GP-2 base model, average gas rate increased with equivalent coal thickness, gas content, Langmuir pressure, stimulated area, and stimulated-region permeability; inverse responses were obtained for cleat-fracture porosity, proportional three-layer initial permeability, initial reservoir pressure, and Langmuir volume. Adsorption time and interlayer spacing had comparatively small effects. These trends are specific to the selected model and parameter ranges and should not be interpreted as validated long-term forecasts or established causal relationships. This study demonstrates a practical way to carry a laboratory-derived stress-sensitivity parameter into a multilayer field model. Full article

Polymer-modified bitumen (PMB) is widely used in motorway pavements due to its proven mechanical performance; however, economic and sustainability considerations have stimulated interest in alternative modification strategies. This study evaluates the mechanical performance of asphalt mixtures incorporating wet-process crumb-rubber-modified bitumen (CRMB) and a dry-process crumb rubber–bitumen concentrate (CRBC) system in comparison with conventional PMB mixtures in a motorway trial section. Particular emphasis was placed on comparing wet- and dry-process rubber modification approaches under the same production and service conditions. Surface and binder-course mixtures were assessed through volumetric characterization, indirect tensile strength ratio (ITSR), indirect tensile stiffness modulus (IT-CY) at 0 °C, 15 °C, and 27 °C, wheel tracking at 50 °C and 60 °C, and semicircular bending (SCB) fracture testing, including laboratory ageing. All mixtures met the relevant specification limits for volumetric properties, water sensitivity (ITSR ≥ 80%), and resistance to permanent deformation. Rubber-modified mixtures exhibited improved resistance to permanent deformation and reduced temperature susceptibility compared with PMB references. Stiffness results indicated improved high-temperature stability for CRBC mixtures, while fracture resistance showed temperature-dependent trends influenced by mixture type and binder modification. Overall, the findings demonstrate that both CRMB and CRBC mixtures achieved mechanical performance comparable to PMB under the evaluated conditions, supporting their use as technically viable alternatives for high-performance motorway pavements while promoting the beneficial reuse of end-of-life tyre rubber. Full article

This study presents an integrated workflow to characterize and optimize hydraulic fracturing operations in horizontal shale reservoirs using passive wellhead pressure monitoring (PWPM). Pressure data from offset wells in the Horn River Shale Basin were analyzed to identify passive pressure responses and distinguish between direct hydraulic communication and stress-induced behavior, providing insight into fracture dynamics and inter-well connectivity. A multivariate sensitivity analysis was performed to evaluate how key fracture and reservoir mechanical properties, fracture orientation, and in situ stresses govern passive pressure signatures. A fully coupled hydro-mechanical model, implemented using a distinct element formulation, was developed based on the observed passive pressure and microseismic data to generate a physics-based representation of fracture propagation and fluid migration. The modeling framework enables forward prediction of passive pressure responses during future stimulation stages, supporting improved treatment design, real-time operational adjustments, and more reliable refracturing strategies under evolving subsurface conditions. By enhancing fracture network characterization and complementing microseismic monitoring, PWPM demonstrates strong diagnostic value for supporting safer and more efficient injection practices in unconventional reservoir development, as well as broader sustainable energy applications. Full article

CO₂ foam fracturing has emerged as a promising stimulation technology for enhancing permeability and improving production performance in deep coalbed methane (CBM) reservoirs while providing additional potential for carbon utilization. However, the multiscale relationship between local mechanical degradation and macroscopic mechanical deterioration and fracture instability induced by CO₂ foam treatment remains insufficiently understood. In this study, four candidate coal samples originating from the Carboniferous–Permian No. 8+9 coal seam system were first comparatively characterized. Based on petrographic characteristics, mineralogical composition, and specimen integrity, representative bright coal and semi-dull coal samples from the Lüliang mining area were selected for subsequent multiscale mechanical investigations. Based on petrographic characteristics, mineralogical composition, and specimen integrity, representative bright coal and semi-dull coal samples from the Lüliang mining area were selected for petrographic analysis, X-ray diffraction (XRD), nanoindentation, conventional triaxial compression, and cracked chevron-notched Brazilian disc (CCNBD) fracture toughness tests. Coal specimens were immersed in CO₂ foam under reservoir-relevant conditions (50 °C, 20 MPa, foam quality of 65%) for different durations (0–6 days), and the coupled evolution of micromechanical properties, macroscopic mechanical behavior, and fracture resistance was evaluated. The results indicate that both coal types exhibit pronounced heterogeneity in maceral composition and mineral distribution. Bright coal is characterized by high vitrinite content and low mineral abundance, whereas semi-dull coal contains higher proportions of inertinite and minerals. Nanoindentation results reveal that mineral-rich regions possess significantly higher Young’s modulus and hardness than organic-matter-rich regions, highlighting pronounced micromechanical heterogeneity within the coal matrix. With increasing immersion time, the micromechanical properties of both coals exhibit a two-stage evolution characterized by rapid initial deterioration followed by a gradual stabilization trend. After 6 days of immersion, the average Young’s modulus and hardness of bright coal decreased by 40% and 30%, respectively, whereas those of semi-dull coal decreased by 30% and 17%. Simultaneously, macroscopic mechanical properties and fracture resistance continuously declined, with fracture toughness reductions of 74% and 55% for bright coal and semi-dull coal, respectively. Compared with semi-dull coal, bright coal exhibited higher damage sensitivity, evolving from dominant single-fracture failure to granular fragmentation, whereas semi-dull coal maintained a multi-crack composite shear failure mode. Combined micromechanical and macroscopic observations suggest that the observed mechanical deterioration may be associated with coupled effects of fluid–coal interaction, matrix softening, and progressive damage evolution. Although pore and crack evolution were not directly observed, the results suggest that coal structure plays an important role in governing damage transfer across scales and thereby influences fracture behavior and mechanical weakening. These findings provide insight into the multiscale mechanical response of coal under CO₂ foam treatment and may support the optimization of stimulation strategies for deep CBM reservoirs. Full article

Unconventional gas-well production is jointly controlled by fracture conductivity, stimulated-region supply, matrix replenishment, boundary propagation, and low-pressure fluid-property changes. In practice, RTA diagnostic curves are often affected by variable operating schedules, pressure-measurement errors, and production disturbances, making flow-stage boundaries difficult to define consistently. To reduce the subjectivity of manual interpretation and to capture stage evolution rather than whole-well classes, an ordered flow-state identification method based on a five-region analytical model and RTA sliding-window features is developed. A fully random, large-sample production-response library is generated with the five-region model. Each well production curve is divided into local time windows, from which dynamic features, including RNP, material-balance time, local slopes, pseudopressure derivatives, and normalized cumulative gas production are extracted. K-means clustering is then used to identify local states, which are reordered by material-balance time to form an ordered S1–S5 sequence. Results from 10,000 synthetic wells yielded 689,394 RTA windows, an inter-cluster separation of 1.8924, a stage-regression rate of 0.0238, and an average of 4.24 states per well. S1–S5 represent early fracture–stimulated-region response, stimulated-region supply development, matrix composite supply transition, enhanced boundary/control-volume effects, and late low-pressure property response, respectively. Application to Well M1 shows that S4 contributes the most gas (37.83%), followed by S5 (23.47%), indicating dominant mid-to-late effective supply and low-pressure long-tail production. The method converts empirical flow-regime division into reproducible and comparable window-state identification results, supporting stage diagnosis and production-strategy adjustment for unconventional gas wells. Full article

Refracturing is an important stimulation technique for improving the productivity of mature shale gas wells. However, for low-productivity horizontal wells, the controlling effects of production history and pre-refracturing energy replenishment on fracture re-initiation and repropagation remain insufficiently quantified. This study focuses on mature wells in the H Block of the Fuling shale gas field. The Jiaoshiba area in the Fuling shale gas field, located on the eastern margin of the Sichuan Basin, is characterized by organic-rich marine shales of the Wufeng–Longmaxi Formation, where gas enrichment is jointly controlled by the Jiaoshiba anticline, fault distribution, and favorable preservation conditions. A three-dimensional geological model was constructed using seismic interpretation, well logging, core analysis, ant-tracking fracture attributes, and field fracturing data. A one-way coupled finite-element workflow was then applied to simulate the evolution of pore pressure and in situ stress during primary production, water-injection energy replenishment, and refracturing. The model was calibrated against historical bottomhole flowing pressure data, with a pressure-response matching accuracy greater than 85%. The results show that a lower initial production (4 × 10⁴ m³/d) allocation can mitigate reservoir pressure depletion and maintain a more favorable stress environment for fracture branching during refracturing. Compared with refracturing after 10 or 20 years of production, refracturing after 5 years produced a stronger post-treatment response in the simulated cases. For water-injection energy replenishment, an injection rate of 700 m³/d restored reservoir pressure and regulated the local stress field more effectively than 500 m³/d, whereas increasing the rate to 1000 m³/d provided only limited additional pressure recovery. Overall, under the simulated reservoir conditions, a technically favorable parameter combination for the target well is an initial production allocation of 4 × 10⁴ m³/d, refracturing after approximately 5 years of production, and one year of pre-refracturing water-injection energy replenishment at about 700 m³/d. These findings provide a reference for refracturing timing and pre-treatment energy-replenishment design in depleted shale gas reservoirs. Full article

As a sustainable alternative to fossil fuels, geothermal energy plays a critical role in the global shift toward carbon neutrality. However, the economic extraction of heat is frequently hindered by poor-reservoir permeability, often exacerbated by mineral scaling and particulate clogging during long-term operation. This review provides a comprehensive synthesis of acidization technologies, emphasizing their mechanisms for enhancing injectivity and productivity in diverse geothermal settings. This study scrutinizes the chemical interaction between varied acid systems ranging from conventional mineral acids to solid organic acid blends and the complex geological conditions of volcanic and sedimentary reservoirs. Furthermore, the paper delineates the evolution of geothermal energy development methods, such as matrix acidizing and hydraulic fracturing synergy (multi-stage acid fracturing), alongside metal corrosion inhibition and effluent scale treatment. By integrating empirical field data with theoretical geochemical modeling, this review provides an in-depth analysis of the acid fracturing mechanisms within coupled thermal–hydraulic–mechanical–chemical (THMC) fields. It further identifies the persistent challenges of high-temperature stability and deep-seated flow path diversion. Ultimately, this paper proposes a roadmap for next-generation “smart” acidizing fluids, aiming to provide a robust framework for optimizing geothermal heat mining and ensuring the longevity of enhanced geothermal systems. Full article

Vertical cross-layer propagation of hydraulic fractures is critical for the efficient stimulation of interbedded sandstone reservoirs in the Lianggaoshan Formation. To investigate the vertical fracture propagation mechanisms and controlling factors in this complex lithological setting, a three-dimensional (3D) numerical model was established using the continuum–discontinuum element method (CDEM) based on the typical “mudstone–sandstone–mudstone” geological structure of the Lianggaoshan Formation. The effects of geological parameters, including interlayer stress contrast, vertical stress contrast, elastic modulus ratio, and reservoir thickness, as well as engineering parameters, including fluid viscosity and injection rate, were systematically evaluated. The results show that interlayer stress contrast is the primary factor restricting vertical fracture growth. As the interlayer stress contrast increases from 2 MPa to 8 MPa, the fracture morphology gradually changes from effective cross-layer propagation to complete containment within the sandstone layer, while the injection pressure at 300 s increases from 55.91 MPa to 58.90 MPa and the fracture width increases from 4.58 mm to 5.05 mm. In contrast, vertical stress contrast has a limited influence under the horizontal-stratification conditions investigated. Increasing fluid viscosity and injection rate can enhance intra-fracture net pressure and promote interface breakthrough. When the fluid viscosity increases from 5 mPa·s to 50 mPa·s, the breakdown pressure increases from 61.05 MPa to 69.59 MPa and the fracture width increases from 4.79 mm to 6.37 mm. When the injection rate increases from 0.6 m³/min to 3.6 m³/min, the breakdown pressure increases from 58.57 MPa to 63.35 MPa and the fracture width increases from 4.28 mm to 5.17 mm. Based on the Effective Vertical Propagation Index (EVI), three vertical propagation modes were identified: restricted vertical propagation, partially effective cross-layer propagation, and effective vertical propagation. Gray Relational Analysis (GRA) revealed the following sensitivity ranking: interlayer stress contrast > injection rate > fluid viscosity > elastic modulus ratio > reservoir thickness > vertical stress contrast. For reservoirs with a typical 4 MPa stress barrier, effective vertical breakthrough can be achieved when the fluid viscosity exceeds 25 mPa·s or the injection rate reaches 3.6 m³/min. These findings provide quantitative guidance for optimizing fracturing parameters in interbedded sandstone reservoirs. Full article

Mature thin oil reservoirs remain pivotal to maintaining reserves, sustaining production, and enhancing profitability due to their substantial annual output and untapped recovery potential. However, prolonged development leads to compromised fracturing efficacy, manifesting as severe formation-energy depletion, rapid production decline, and short effective periods of stimulation measures. Energy-storage fracturing technology addresses these challenges through fluid-injection energization and imbibition displacement, thereby replenishing formation energy and mobilizing residual oil. Leveraging a geo-engineering integrated platform, this study establishes an inverted seven-spot well-pattern energization model to systematically investigate pore pressure–stress field evolution and dynamic responses under varying energization parameters, including energy-storage injection rate, energy-storage volume, and energy-storage sequence. Key findings include: (1) increasing the energy-storage injection rate from 1.5 m³/min to 3.5 m³/min elevates average pore pressure by 7.8 MPa, with minimum and maximum horizontal principal stresses increasing by 1.4 MPa and 1.7 MPa, respectively; (2) raising the energy-storage volume from 2800 m³ to 4200 m³ enhances pore pressure by 5.5 MPa, accompanied by 2.5 MPa and 2.6 MPa increments in minimum and maximum horizontal principal stresses; (3) simultaneous energizing of all injection wells (1–6) is identified as the optimal injection sequence, yielding the highest average pore pressure of 40.3 MPa at equivalent monitoring positions within the well group, with corresponding average minimum and maximum horizontal principal stresses of 55.3 MPa and 60.3 MPa, respectively. The results provide theoretical and technical support for optimizing energy-storage fracturing strategies in mature thin oil reservoirs. Full article